[0001] The present invention relates to methods and apparatus for separating and joining
tubulars in a wellbore; more particularly, the present invention relates to cutting
a tubular in a wellbore using rotational and radial forces brought to bear against
a wall of the tubular.
[0002] In the completion and operation of hydrocarbon wells, it is often necessary to separate
one piece of a downhole tubular from another piece in a wellbore. In most instances,
bringing the tubular back to surface for a cutting operation is impossible and in
all instances it is much more efficient in time and money to separate the pieces in
the wellbore. The need to separate tubulars in a wellbore arises in different ways.
For example, during drilling and completion of an oil well, tubulars and downhole
tools mounted thereon are routinely inserted and removed from the wellbore. In some
instances, tools or tubular strings become stuck in the wellbore leading to a "fishing"
operation to locate and remove the stuck portion of the apparatus. In these instances,
it is often necessary to cut the tubular in the wellbore to remove the run-in string
and subsequently remove the tool itself by milling or other means. In another example,
a downhole tool such as a packer is run into a wellbore on a run-in string of tubular.
The packing member includes a section of tubular or a "tail pipe" hanging from the
bottom thereof and it is advantageous to remove this section of tail pipe in the wellbore
after the packer has been actuated. In instances where workover is necessary for a
well which has slowed or ceased production, downhole tubulars routinely must be removed
in order to replace them with new or different tubulars or devices. For example, un-cemented
well casing may be removed from a well in order to reuse the casing or to get it out
of the way in a producing well.
[0003] In yet another example, plug and abandonment methods require tubulars to be cut in
a wellbore such as a subsea wellbore in order to seal the well and conform with rules
and regulations associated with operation of an oil well offshore. Because the interior
of a tubular typically provides a pathway clear of obstructions, and because any annular
space around a tubular is limited, prior art devices for downhole tubular cutting
typically operate within the interior of the tubular and cut the wall of the tubular
from the inside towards the outside.
[0004] A prior art example of an apparatus designed to cut a tubular in this fashion includes
a cutter run into the interior of a tubular on a run-in string. As the tool reaches
a predetermined area of the wellbore where the tubular will be separated, cutting
members in the cutting tool are actuated hydraulically and swing outwards from a pivot
point on the body of the tool. When the cutting members are actuated, the run-in string
with the tool therebelow is rotated and the tubular therearound is cut by the rotation
of the cutting members. The foregoing apparatus has some disadvantages. For instance,
the knives are constructed to swing outward from a pivot point on the body of the
cutting tool and in certain instances, the knives can become jammed between the cutting
tool and the interior of the tubular to be cut. In other instances, the cutting members
can become jammed in a manner which prevents them from retracting once the cutting
operation is complete. In still other examples, the swinging cutting members can become
jammed with the lower portion of tubular after it has been separated from the upper
portion thereof. Additionally, this type of cutter creates cuttings that are difficult
to remove and subsequently causes problems for other downhole tools.
[0005] An additional problem associated conventional downhole cutting tools includes the
cost and time associated with transporting a run-in string of tubular to a well where
a downhole tubular is to be cut. Run-in strings for the cutting tools are expensive,
must be long enough to reach that section of downhole tubular to be cut, and require
some type of rig in order to transport, bear the weight of, and rotate the cutting
tool in the wellbore. Because the oil wells requiring these services are often remotely
located, transporting this quantity of equipment to a remote location is expensive
and time consuming. While coil tubing has been utilized as a run-in string for downhole
cutters, there is still a need to transport the bulky reel of coil tubing to the well
site prior to performing the cutting operation.
[0006] Other conventional methods and apparatus for cutting tubulars in a wellbore rely
upon wireline to transport the cutting tool into the wellbore. However, in these instances
the actual separation of the downhole tubular is performed by explosives or chemicals,
not by a rotating cutting member. While the use of wireline in these methods avoids
time and expense associated with run-in strings of tubulars or coil tubing, chemicals
and explosives are dangerous, difficult to transport and the result of their use in
a downhole environment is always uncertain.
[0007] There is a need therefore, for a method and apparatus for separating downhole tubulars
which is more effective and reliable than conventional, downhole cutters. There is
yet a further need for an effective method and apparatus for separating downhole tubulars
which does not rely upon a run-in string of tubular or coil tubing to transport the
cutting member into the wellbore. There is yet a further need for a method and apparatus
of separating downhole tubulars which does not rely on explosives or chemicals. There
is a yet a further need for methods and apparatus for connecting a first tubular to
a second tubular downhole while ensuring a strong connection therebetween.
[0008] US 1,739,932 discloses a casing cutter tool that uses air or water to drive a plunger and wedge-shaped
portion axially downwards through the tool, which in turn pushes cutters radially
outwards to engage and cut the casing.
[0009] US 2,214,226 discloses a method and apparatus for drilling and producing wells, in which explosive
means are used to expand a casing, followed by a separate cutting operation to remove
parts of the casing.
[0010] US 5,787,984 discloses a method and device for casing a well with a composite and initially folded
preform member that is radially unfolded by applying an internal pressure. Separate
cutting means are then used to disconnect lower seal means of the unfolded preform
member.
[0012] According to a first aspect of the present invention, there is provided a method
of joining tubulars in a wellbore comprising: running a first tubular into the wellbore,
an upper end of a section of the first tubular being supported by a bearing on the
run-in string, the run-in string having a cutting tool and an expansion tool disposed
thereon below the bearing and within the first tubular, and the expansion tool being
disposed below the cutting tool; using the expansion tool to expand a portion of the
first tubular into a portion of a second tubular fixed in the wellbore, whereby, after
expanding, the first tubular is supported in the wellbore by interference between
the first tubular and the second tubular; using the cutting tool to sever the first
tubular above that portion of the first tubular which has been expanded in the expanding
step; and removing the run-in string and an upper portion of the first tubular from
the wellbore after the expanding and severing steps.
[0013] The method may further include the step of expanding a remaining portion of a lower
portion of the first tubular after the first tubular is severed.
[0014] The first tubular and the second tubular may initially be joined only in certain
locations and not circumferentially, thereby maintaining a fluid path between the
first tubular and the second tubular.
[0015] In the severing step the cutting tool may separate the first tubular into an upper
and a lower portion through rotational and radial force.
[0016] According to a second aspect of the present invention, there is provided an apparatus
for joining a first tubular to a second tubular in a wellbore, comprising: a run-in
string disposable in the wellbore, the run-in string having a bearing for supporting
an upper end of a section of the first tubular; a cutting tool disposed on the run-in
string, the cutting tool being configured for transversely severing the first tubular
therearound into an upper and a lower portion; and an expansion tool disposed on the
run-in string below the cutting tool, the expansion tool being configured for expanding
the first tubular therearound.
[0017] The bearing may further permit rotation of the run-in string in relation to the first
tubular.
[0018] It may be that the cutting tool is a rotatable cutting tool, having a body with at
least one opening formed in a wall thereof and at least one cutter assembly disposed
within the body, the cutter assembly including at least one hydraulically actuatable,
radially extendable cutter arranged to contact the inside wall of the first tubular
therearound, and the expansion tool having a body with at least one opening formed
in a wall thereof and at least one roller assembly disposed within the body, the roller
assembly including at least one hydraulically actuatable, radially extendable roller
arranged to contact the inside wall of the liner therearound and, through radial force
and rotational movement, to sever the first tubular.
[0019] The first tubular may be a liner and the second tubular may be a casing fixed in
the wellbore. This provides a method and apparatus for setting a liner in a wellbore.
[0020] An embodiment of the present invention provides methods and apparatus for cutting
tubulars in a wellbore. In one embodiment of the invention, a cutting tool having
radially disposed rolling element cutters is provided for insertion into a wellbore
to a predetermined depth where a tubular therearound will be cut into an upper and
lower portion. The cutting tool is constructed and arranged to be rotated while the
actuated cutters exert a force on the inside wall of the tubular, thereby severing
the tubular therearound. In one embodiment, the apparatus is run into the well on
wireline which is capable of bearing the weight of the apparatus while supplying a
source of electrical power to at least one downhole motor which operates at least
one hydraulic pump. The hydraulic pump operates a slip assembly to fix the downhole
apparatus within the wellbore prior to operation of the cutting tool. Thereafter,
the pump operates a downhole motor to rotate the cutting tool while the cutters are
actuated.
[0021] In another embodiment of the invention, the cutting tool is run into the wellbore
on a run-in string of tubular. Fluid power to the cutter is provided from the surface
of the well and rotation of the tool is also provided from the surface through the
tubular string. In another embodiment, the cutting tool is run into the wellbore on
pressurizable coiled tubing to provide the forces necessary to actuate the cutting
members and a downhole motor providing rotation to the cutting tool.
[0022] In another embodiment of the invention, the apparatus includes a cutting tool having
hydraulically actuated cutting members, a fluid filled pressure compensating housing,
a torque anchor section with hydraulically deployed slips, a brushless dc motor with
a source of electrical power from the surface, and a reduction gear box to step down
the motor speed and increase the torque to the cutting tool, as well as one or more
hydraulic pumps to provide activation pressure for the slips and the cutting tool.
In operation, the anchor activates before the rolling element cutters thereby allowing
the tool to anchor itself against the interior of the tubular to be cut prior to rotation
of the cutting tool. Hydraulic fluid to power the apparatus is provided from a pressure
compensated reservoir. As oil is pumped into the actuated portions of the apparatus,
the compensation piston moves downward to take up space of used oil.
[0023] In yet another embodiment of the invention, an expansion tool and a cutting tool
are both used to affix a tubular string in a wellbore. In this embodiment, a liner
is run into a wellbore and is supported by a bearing on a run-in string. Disposed
on the run-in string, inside of an upper portion of the liner is a cutting tool and
therebelow an expansion tool. As the apparatus reaches a predetermined location of
the wellbore, the expander is actuated hydraulically and the liner portion therearound
is expanded into contact with the casing therearound. Thereafter, with the weight
of the liner transferred from the run-in string to the newly formed joint between
the liner and the casing, the expander is de-actuated and the cutter disposed thereabove
on the run-in string is actuated. The cutter, through axial and rotational forces,
separates the liner into an upper and lower portion. Thereafter, the cutter is de-actuated
and the expander therebelow is re-actuated. The expansion tool expands that portion
of the liner remaining thereabove and is then de-actuated. After the separation and
expanding operations are complete, the run-in string, including the cutter and expander
are removed from the wellbore, leaving the liner in the wellbore with a joint between
the liner and the casing therearound sufficient to fix the liner in the wellbore.
[0024] In yet another embodiment, the invention provides apparatus and methods to join tubulars
in a wellbore providing a connection therebetween with increased strength that facilitates
the expansion of one tubular into another.
[0025] So that the manner in which the above recited features, advantages and objects of
the present invention are attained and can be understood in detail, a more particular
description of the invention, briefly summarized above, may be had by reference to
the embodiments thereof which are illustrated in the appended drawings.
[0026] It is to be noted, however, that the appended drawings illustrate only typical embodiments
of this invention and are therefore not to be considered limiting of its scope, for
the invention may admit to other equally effective embodiments. In the drawings:
Figure 1 is a perspective view of the cutting tool of the present invention.
Figure 2 is a perspective end view in section, thereof.
Figure 3 is an exploded view of the cutting tool.
Figure 4 is a section view of the cutting tool disposed in a wellbore at the end of
a run-in string and having a tubular therearound.
Figure 5 is a section view of the apparatus of Figure 4, wherein cutters are actuated
against the inner wall of the tubular therearound.
Figure 6 is a view of a well, partially in section, illustrating a cutting tool and
a mud motor disposed on coil tubing.
Figure 7 is a section view of a wellbore illustrating a cutting tool, mud motor and
tractor disposed on coil tubing.
Figure 8 is a section view of an apparatus including a cutting tool, motor/pump and
slip assembly disposed on a wireline.
Figure 9 is a section view of the apparatus of Figure 6, with the cutting tool and
a slip assembly actuated against the inner wall of a tubular therearound.
Figure 10 is a section view of a liner hanger apparatus including a liner portion,
and run-in string with a cutting tool and an expansion tool disposed thereon.
Figure 11 is an exploded view of the expansion tool.
Figure 12 is a section view of the liner hanger apparatus of Figure 8 illustrating
a section of the liner having been expanded into the casing therearound by the expansion
tool.
Figure 13 is a section view of the liner hanger apparatus with the cutting tool actuated
in order to separate the liner therearound into an upper and lower portion.
Figure 14 is a section view of the liner hanger apparatus with an additional portion
of the liner expanded by the expansion tool.
Figure 15 is a perspective view of a tubular for expansion into and connection to
another tubular.
Figure 16 is the tubular of Figure 15 partially expanded into contact with an outer
tubular.
Figure 17 is the tubular of Figure 16 fully expanded into the outer tubular with a
seal therebetween.
Figure 18 is an alternative embodiment of a tubular for expansion into and in connection
to another tubular.
Figure 19 is a section view of the tubular of Figure 18 with a portion thereof expanded
into a larger diameter tubular therearound and illustrating a fluid path of fluid
through an annulus area.
Figure 20 is a section view of the tubular of Figure 18 completely expanded into the
larger diameter tubular therearound.
[0027] Figures 1 and 2 are perspective views of the cutting tool 100 of the present invention.
Figure 3 is an exploded view thereof. The tool 100 has a body 102 which is hollow
and generally tubular with conventional screw-threaded end connectors 104 and 106
for connection to other components (not shown) of a downhole assembly. The end connectors
104 and 106 are of a reduced diameter (compared to the outside diameter of the longitudinally
central body part 108 of the tool 100), and together with three longitudinal flutes
110 on the central body part 108, allow the passage of fluids between the outside
of the tool 100 and the interior of a tubular therearound (not shown). The central
body part 108 has three lands 112 defined between the three flutes 110, each land
112 being formed with a respective recess 114 to hold a respective roller 116. Each
of the recesses 114 has parallel sides and extends radially from the radially perforated
tubular core 115 of the tool 100 to the exterior of the respective land 112. Each
of the mutually identical rollers 116 is near-cylindrical and slightly barreled with
a single cutter 105 formed thereon. Each of the rollers 116 is mounted by means of
a bearing 118 (Figure 3) at each end of the respective roller for rotation about a
respective rotation axis which is parallel to the longitudinal axis of the tool 100
and radially offset therefrom at 120-degree mutual circumferential separations around
the central body 108. The bearings 118 are formed as integral end members of radially
slidable pistons 120, one piston 120 being slidably sealed within each radially extended
recess 114. The inner end of each piston 120 (Figure 2) is exposed to the pressure
of fluid within the hollow core of the tool 100 by way of the radial perforations
in the tubular core 115.
[0028] By suitably pressurizing the core 115 of the tool 100, the pistons 120 can be driven
radially outwards with a controllable force which is proportional to the pressurization,
and thereby the rollers 116 and cutters 105 can be forced against the inner wall of
a tubular in a manner described below. Conversely, when the pressurization of the
core 115 of the tool 100 is reduced to below whatever is the ambient pressure immediately
outside the tool 100, the pistons 120 (together with the piston-mounted rollers 116)
are allowed to retract radially back into their respective recesses 114.
[0029] Figure 4 is a section view of the cutting tool 100 disposed at the end of a tubular
run-in string 101 in the interior of a tubular 150. In the embodiment shown, the tubular
150 is a liner portion functioning to line a borehole. However, it will be understood
that the cutting tool 100 could be used to sever any type of tubular in a wellbore
and the invention is not limited to use with a tubular lining the borehole of a well.
The run-in string 101 is attached to a first end connector 106 of the cutting tool
100 and the tool is located at a predetermined position within the tubular 150. With
the cutting tool 100 positioned in the tubular 150, a predetermined amount of fluid
pressure is supplied through the run-in string 101. The pressure is adequate to force
the pistons 120 and the rollers 116 with their cutters 105 against the interior of
the tubular. With adequate force applied, the run-in string 101 and cutting tool 100
are rotated in the tubular, thereby causing a groove of ever increasing depth to be
formed around the inside of the tubular 150. Figure 5 is a section view of the apparatus
of Figure 4 wherein the rollers 116 with their respective cutters 105 are actuated
against the inner surface of the tubular 150. With adequate pressure and rotation,
the tubular is separated into an upper 150a and lower 150b portions. Thereafter, with
a decrease in fluid pressure, the rollers 116 are retracted and the run-in string
101 and cutting tool 100 can be removed form the wellbore.
[0030] Figure 6 illustrates an alternative embodiment of the invention including a cutting
tool 100 disposed in a wellbore 160 on a run-in string 165 of coil tubing. A mud motor
170 is disposed between the lower end of the coil tubing string 165 and the cutting
tool 100 and provides rotational force to the tool 100. In this embodiment, pressurized
fluid adequate to actuate the rollers 116 with their cutters 105 is provided in the
coil tubing string 165 The mud 170 motor is also operated by fluid in the coil tubing
string 165 and an output shaft of the mud motor is coupled to an input shaft of the
cutting tool 100 to provide rotation to the cutting tool 100. Also illustrated in
Figure 6 is a coil tubing reel 166 supplying tubing which is run into the wellbore
160 through a conventional wellhead assembly 168. With the use of appropriate known
pressure containing devices, the cutting tool 100 can be used in a live well.
[0031] Figure 7 is a section view illustrating a cutting tool 100 disposed on coil tubing
165 in a wellbore 160 with a mud motor 170 and a tractor 175 disposed thereabove.
As in the embodiment of Figure 6, the cutting tool 100 receives a source of pressurized
fluid for actuation from the coil tubing string 165 thereabove. The mud motor 170
provides rotational force to the cutter. Additionally, the tractor 175 provides axial
movement necessary to move the cutting tool assembly in the wellbore. The tractor
is especially useful when gravity alone would not cause the necessary movement of
the cutting tool 100 in the wellbore 160. Axial movement can be necessary in order
to properly position the cutting tool 100 in a non-vertical wellbore, like a horizontal
wellbore. Tractor 175, like the cutting tool includes a number of radially actuable
rollers 176 that extend outward to contact the inner wall of a tubular 150 therearound.
The spiral arrangement of the rollers 176 on the body 177 of the tractor 175 urge
the tractor axially when rotational force is applied to the tractor body 177.
[0032] Figure 8 is a section view of an apparatus 200 including the cutting tool 100 disposed
in a tubular 150 on wireline 205. In use, the apparatus 200 is run into a wellbore
on wireline extending from the surface of the well (not shown). The wireline 205 serves
to retain the weight of the apparatus 200 and also provide a source of power electrical
to components of the apparatus. The apparatus 200 is designed to be lowered to a predetermined
depth in a wellbore where a tubular 150 therearound is to be separated. Included in
the apparatus 200 is a housing 210 having a fluid reservoir 215 with a pressure compensating
piston (not shown), a hydraulically actuated slip assembly 220 and a cutting tool
100 disposed below the housing 210. The pressure compensating piston 215 allows fluid
in the reservoir 215 to expand and contract with changes in pressure and isolates
the fluid in the reservoir fluid from wellbore fluid therearound. Disposed between
the slip assembly 220 and the cutting tool 100 is a brushless dc motor 225 powering
two reciprocating hydraulic pumps 230, 235 and providing rotational movement to the
cutter tool 100. Each pump is in fluid communication with reservoir 215. The upper
pump 230 is constructed and arranged to provide pressurized fluid to the slip assembly
220 in order to cause slips to extend outwardly and contact the tubular 150 therearound.
The lower pump 235 is constructed and arranged to provide pressurized fluid to the
cutting tool 100 in order to actuate rollers 116 and cutters 105 and force them into
contact with the tubular 150 therearound. A gearbox 240 is preferably disposed between
the output shaft of the motor and the rotational shaft of the cutting tool. The gearbox
240 functions to provide increased torque to the cutting tool 100. The pumps 230,
235 are preferably axial piston, swash plate-type pumps having axially mounted pistons
disposed alongside the swash plate. The pumps are designed to alternatively actuate
the pistons with the rotating swash plate, thereby providing fluid pressure to the
components. However, either pump 230, 235 could also be a plain reciprocating, gear
rotor or spur gear-type pump. The upper pump, disposed above the motor 225, preferably
runs at a higher speed than the lower pump ensuring that the slip assembly 220 will
be actuated and will hold the apparatus 200 in a fixed position relative to the tubular
150 before the cutters 105 contact the inside wall of the tubular. The apparatus 200
will thereby anchor itself against the inside of the tubular 150 to permit rotational
movement of the cutting tool 100 therebelow.
[0033] Hydraulic fluid to power the both the upper 230 and lower 235 pumps is provided from
the pressure compensated reservoir 215. As fluid is pumped behind a pair of slip members
245a, 245b located on the slip assembly 220, the compensation piston will move in
order to take up space of the fluid as it is utilized. Likewise, the rollers 116 of
the cutting tool 100 operate on pressurized fluid from the reservoir 215.
[0034] The slip members 245a, 245b and the radially slidable pistons 120 housing the rollers
116 and cutters 105 preferably have return springs installed therebehind which will
urge the pistons 245a, 245b, 120 to a return or a closed position when the power is
removed and the pumps 230, 235 have stopped operating. Residual pressure within the
system is relieved by means of a control orifice or valves in the supply line (not
shown) to the pistons 245a, 245b, 120 of the slip assembly and the cutting tool 100.
The valves or controlled orifices are preferably set to dump oil at a much lower rate
than the pump output. In this manner, the apparatus of the present invention can be
run into a wellbore to a predetermined position and then operated by simply supplying
power from the surface via the wireline 205 in order to fix the apparatus 200 in the
wellbore and cut the tubular. Finally, after the tubular 150 has been severed and
power to the motor 225 has been removed, the slips 246a, 246b and cutters 105 will
de-actuate with the slips 246a, 246b and the cutters 105 returning to their respective
housings, allowing the apparatus 200 to be removed from the wellbore.
[0035] Figure 9 is a section view of the apparatus 200 of Figure 9 with the slip assembly
220 actuated and the cutting tool 100 having its cutting surfaces 105 in contact with
the inside wall of the tubular 150. In operation, the apparatus 200 is run into the
wellbore on a wireline 205. When the apparatus reaches a predetermined location in
the wellbore or within some tubular therein to be severed, power is supplied to the
brushless dc motor 225 through the wireline 205. The upper pump 230, running at a
higher speed than the lower pump 235, operates the slip assembly 220 causing the slips
246a, 246b to actuate and grip the inside surface of the tubular 150. Thereafter,
the lower hydraulic pump 235 causes the cutters 105 to be urged against the tubing
150 at that point where the tubing is to be severed and the cutting tool 100 begins
to rotate. Through rotation of the cutting tool 100 and radial pressure of the cutters
105 against the inside wall of the tubular 150, the tubular can be partially or completely
severed and an upper portion 150a of the tubing separated from a lower portion 150b
thereof. At the completion of the operation, power is shut off to the apparatus 200
and through a spring biasing means, the cutters 105 are retracted into the body of
the cutting tool 100 and the slips 246a, 246b retract into the housing of the slip
assembly 220. The apparatus 200 may then be removed from the wellbore. In an alternative
embodiment, the slip assembly 220 can be caused to stay actuated whereby the upper
portion 150a of the severed tubular 150 is carried out of the well with the apparatus
200.
[0036] Figure 10 is a section view showing another embodiment of the invention. In this
embodiment, an apparatus 300 for joining downhole tubulars and then severing a tubular
above the joint is provided. The apparatus 300 is especially useful in fixing or hanging
a tubular in a wellbore and utilizes a smaller annular area than is typically needed
for this type operation. The apparatus 300 includes a run-in tubular 305 having a
cutting tool 100 and an expansion tool 400 disposed thereon.
[0037] Figure 11 is an exploded view of the expansion tool. The expansion tool 400, like
the cutting tool 100 has a body 402 which is hollow and generally tubular with connectors
404 and 406 for connection to other components (not shown) of a downhole assembly.
The end connectors 404 and 406 are of a reduced diameter (compared to the outside
diameter of the longitudinally central body 402 of the tool 400), and together with
three longitudinal flutes 410 on the body 402, allow the passage of fluids between
the outside of the tool 400 and the interior of a tubular therearound (not shown).
The body 402 has three lands 412 defined between the three flutes 410, each land 412
being formed with a respective recess 414 to hold a respective roller 416. Each of
the recesses 414 has parallel sides and extends radially from the radially perforated
tubular core 415 of the tool 400 to the exterior of the respective land 412. Each
of the mutually identical rollers 416 is near-cylindrical and slightly barreled. Each
of the rollers 416 is mounted by means of a bearing 418 at each end of the respective
roller for rotation about a respective rotation axis which is parallel to the longitudinal
axis of the tool 400 and radially offset therefrom at 120-degree mutual circumferential
separations around the central body 408. The bearings 418 are formed as integral end
members of radially slidable pistons 420, one piston 420 being slidably sealed within
each radially extended recess 414. The inner end of each piston 420 is exposed to
the pressure of fluid within the hollow core of the tool 400 by way of the radial
perforations in the tubular core 415 (Figure 10).
[0038] Referring again to Figure 10, also disposed upon the run-in string and supported
thereon by a bearing member 310 is a liner portion 315 which is lowered into a wellbore
along with the apparatus 300 for installation therein. In the embodiment shown in
Figure 10, the bearing member 310 supports the weight of the liner portion 315 and
permits rotation of the run-in string independent of the liner portion 315. The liner
315 consists of tubular having a first, larger diameter portion 315a which houses
the cutting tool 100 and expansion tool 400 and a tubular of a second, small diameter
315b therebelow. One use of the apparatus 300 is to fix the liner 315 in existing
casing 320 by expanding the liner into contact with the casing and thereafter, severing
the liner at a location above the newly formed connection between the liner 315 and
the casing 320.
[0039] Figure 12 is a section view of the apparatus 300 illustrating a portion of the larger
diameter tubular 315a having been expanded into casing 320 by the expanding tool 400.
As is visible in the Figure, the expanding tool 400 is actuated and through radial
force and axial movement, has enlarged a given section of the tubular 315a therearound
once the tubular 315 is expanded into the casing 325, the weight of the liner 315
is borne by the casing 325 therearound, and the run-in string 305 with the expanding
400 and cutting 105 tools can independently move axially within the wellbore. Preferably,
the tubular 315 and casing 325 are initially joined only in certain locations and
not circumferentially. Consequently, there remains a fluid path between the liner
and casing and any cement to be circulated in the annular area between the casing
325 and the outside diameter of the liner 315 can be introduced into the wellbore
330.
[0040] Figure 13 is a section view of the apparatus 300 whereby the cutting tool 100 located
on the run-in string 305 above the expansion tool 400 and above that portion of the
liner which has been expanded, is actuated and the cutters 105, through rotational
and radial force, separate the liner into an upper and lower portion. This step is
typically performed before any circulated cement has cured in the annular area between
the liner 315 and casing 320. Finally, Figure 14 depicts the apparatus 300 of the
present invention in the wellbore after the liner 315 has been partially expanded,
severed and separated into an upper and lower portion and the upper portion of the
expanded liner 315 has been "rolled out" to give the new liner and the connection
between the liner and the casing a uniform quality. At the end of this step, the cutter
100 and expander 400 are de-actuated and the piston surfaces thereon are retracted
into the respective bodies. The run-in string is then raised to place the bearing
310 in contact with shoulder member at the top of the liner 315. The apparatus 300
can then be removed from the wellbore along with the run-in string 305, leaving the
liner installed in the wellbore casing.
[0041] As the foregoing demonstrates, the present invention provides an easy efficient way
to separate tubulars in a wellbore without the use of a rigid run-in string. Alternatively,
the invention provides a trip saving method of setting a string of tubulars in a wellbore.
Also provided is a space saving means of setting a liner in a wellbore by expanding
a first section of tubular into a larger section of tubular therearound.
[0042] As illustrated by the foregoing, it is possible to form a mechanical connection between
two tubulars by expanding the smaller tubular into the inner surface of the larger
tubular and relying upon friction therebetween to affix the tubulars together. In
this manner, a smaller string of tubulars can be hung from a larger string of tubulars
in a wellbore. In some instances, it is necessary that the smaller diameter tubular
have a relatively thick wall thickness in the area of the connection in order to provide
additional strength for the connection as needed to support the weight of a string
of tubulars therebelow that may be over 1,000 ft. in length. In these instances, expansion
of the tubular can be frustrated by the excessive thickness of the tubular wall. For
instance, tests have shown that as the thickness of a tubular wall increases, the
outer surface of the tubular can assume a tensile stress as the interior surface of
the wall is placed under a compressive radial force necessary for expansion. When
using the expansion tool of the present invention to place an outwardly directed radial
force on the inner wall of a relating thick tubular, the expansion tool, with its
actuated rollers, places the inner surface of the tubular in compression. While the
inside surface of the wall is in compression, the compressive force in the wall will
approach a value of zero and subsequently take on a tensile stress at the outside
surface of the wall. Because of the tensile stress, the radial forces applied to the
inner surface of the tubular may be inadequate of efficiently expand the outer wall
past its elastic limits.
[0043] In order to facilitate the expansion of tubulars, especially those requiring a relatively
thick wall in the area to be expanded, formations are created on the outer surface
of the tubular as shown in Figure 15. Figure 15 is a perspective view of a tubular
500 equipped with threads at a first end to permit installation on an upper end of
a tubular string (not shown). The tubular includes substantially longitudinal formations
502 formed on an outer surface thereof. The formations 502 have the effect of increasing
the wall thickness of the tubular 500 in the area of the tubular to be expanded into
contact with an outer tubular. This selective increase in wall thickness reduces the
tensile forces developed on the outer surface of the tubular wall and permits the
smaller diameter tubular to be more easily expanded into the larger diameter tubular.
In the example shown in Figure 15, the formations 502 and grooves 504 formed on the
outer surface of the tubular 500 therebetween are not completely longitudinal but
are spiraled in their placement along the tubular wall. The spiral shape of the grooves
and formations facilitate the flow of fluids, like cement and also facilitate the
expansion of the tubular wall as it is acted upon by an expansion tool. Additionally,
formed on the outer surface of formations 502 are slip teeth 506 which are specifically
designed to contact the inner surface of a tubular therearound, increasing frictional
resistance to downward axial movement. In this manner, the tubular can be expanded
in the area of the formations 502 and the formations, with their teeth 506 will act
as slips to prevent axial downward movement of the tubing string prior to cementing
of the tubular string in the wellbore. Formed on the outer surface of the tubular
500 above the formations 502 are three circumferential grooves 508 which are used
with seal rings (not shown) to seal the connection created between the expanded inner
tubular 500 and an outer tubular.
[0044] Figure 16 is a section view of the tubular 500 with that portion including the formations
502 expanded into contact with a larger diameter tubular 550 therearound. As illustrated
in Figure 16, that portion of the tubular including the formations has been expanded
outwards through use of an expansion tool (not shown) to place the teeth 506 formed
on the formations 502 into frictional contact with the larger tubular 550 therearound.
Specifically, an expansion tool operated by a source of pressurized fluid has been
inserted into the tubular 500 and through selective operation, expanded a portion
of tubular 500. The spiral shape of the formations 502 has resulted in a smoother
expanded surface of the inner tubular as the rollers of the expansion tool have moved
across the inside of the tubular at an angle causing the rollers to intersect the
angle of the formations opposite the inside wall of the tubular 500. In the condition
illustrated in Figure 16, the weight of the smaller diameter tubular 500 (and any
tubular string attached thereto) is borne by the larger diameter tubular 550. However,
the grooves 504 defined between the formations 502 permit fluid, like cement to circulate
through the expanded area between the tubulars 500, 550.
[0045] Figure 17 is a section view of the tubular 500 of Figure 16 wherein the upper portion
of the tubular 500 has also been expanded into the inner surface of the larger diameter
tubular 550 to effect a seal therebetween. As illustrated, the smaller tubular is
now mechanically and sealingly attached to the outer tubular through expansion of
the formations 502 and the upper portion of the smaller tubular 550 with its circumferential
grooves 508. Visible in Figure 16, the grooves 508 include rings 522 made of some
elastomeric material that serves to seal the annular area between the tubulars 500,
550 when expanded into contact with each other. Typically, this step is performed
after cement has been circulated around the connection point but prior to the cement
having cured.
[0046] In use, the connection would be created as follows: A tubular string 500 with the
features illustrated in Figure 15 is lowered into a wellbore to a position whereby
the formations 502 are adjacent the inner portion of an outer tubular 550 where a
physical connection between the tubulars is to be made. Thereafter, using an expansion
tool of the type disclosed herein, that portion of the tubular bearing the formations
is expanded outwardly into the outer tubular 550 whereby the formations 502 and any
teeth formed thereupon are placed in frictional contact with the tubular 550 therearound.
Thereafter, with the smaller diameter tubular fixed in place with respect to the larger
diameter outer tubular 550, any fluids, including cement are circulated through an
annular area created between the tubulars 500, 550 or tubular 500 and a borehole therearound.
The grooves 504 defined between the formations 502 of the tubular 500 permit fluid
to pass therethrough even after the formations have been urged into contact with the
outer tubular 550 through expansion. After any cement has been circulated through
the connection, and prior to any cement curing, the connection between the inner and
outer tubulars can be sealed. Using the expansion tool described herein, that portion
of the tubular having the circumferential grooves 508 therearound with rings 522 of
elastomeric material therein is expanded into contact with the outer tubular 550.
A redundant sealing means over the three grooves 508 is thereby provided.
[0047] In another aspect, the invention provides a method and apparatus for expanding a
first tubular into a second and thereafter, circulating fluid between the tubulars
through a fluid path independent of the expanded area of the smaller tubular. Figure
18 is a section view of a first, smaller diameter tubular 600 coaxially disposed in
an outer, larger diameter tubular 650. As illustrated, the upper portion of the smaller
diameter tubular includes a circumferential area 602 having teeth 606 formed on an
outer surface thereof which facilitate the use of the circumferential area 602 as
a hanger portion to fixedly attach the smaller diameter tubular 600 within the larger
diameter tubular 650. In the illustration shown, the geometry of the teeth 606 formed
on the outer surface of formations 602 increase the frictional resistance of a connection
between the tubulars 600, 650 to a downward force. Below the circumferential area
602 are two apertures 610 formed in a wall of the smaller diameter tubular 600. The
purpose of apertures 610 is to permit fluid to pass from the outside of the smaller
diameter tubular 600 to the inside thereof as will be explained herein. Below the
apertures 610 are three circumferential grooves 620 formed in the wall of the smaller
diameter tubular 600. These grooves 620 aid in forming a fluid tight seal between
the smaller diameter and larger diameter tubulars 600, 650. The grooves 620 would
typically house rings 622 of elastomeric material to facilitate a sealing relationship
with a surface therearound. Alternatively, the rings could be any malleable material
to effect a seal. Also illustrated in Figure 18 is a cone portion 629 installed at
the lower end of a tubular string 601 extending from the tubular 600. The cone portion
629 facilitates insertion of the tubular 601 into the wellbore.
[0048] Figure 19 is a section view of the smaller 600 and larger 650 diameter tubulars of
Figure 18 after the smaller diameter tubular 600 has been expanded in the circumferential
area 602. As illustrated in Figure 19, area 602 with teeth 606 has been placed into
frictional contact with the inner surface of the larger tubular 650. At this point,
the smaller diameter tubular 600 and any string of tubular 601 attached therebelow
is supported by the outer tubular 650. However, there remains a clear path for fluid
to circulate in an annular area formed between the two tubulars as illustrated by
arrows 630. The arrows 630 illustrate a fluid path from the bottom of the tubular
string 601 upwards in an annulus formed between the two tubulars and through apertures
610 formed in smaller diameter tubular 600. In practice, cement would be delivered
into the tubular 610 to some point below the apertures 610 via a conduit (not shown).
A sealing mechanism around the conduit (not shown) would urge fluid returning though
apertures 610 towards the upper portion of the wellbore.
[0049] Figure 20 is a section view of the smaller 600 and larger 650 diameter tubulars.
As illustrated in Figure 20, that portion of the smaller diameter tubular 600 including
sealing grooves 620 with their rings 622 of elastomeric material have been expanded
into the larger diameter tubular 650. The result is a smaller diameter tubular 600
which is joined by expansion to a larger diameter tubular 650 therearound with a sealed
connection therebetween. While the tubulars 600, 650 are sealed by utilizing grooves
and eleastomeric rings in the embodiment shown, any material could be used between
the tubulars to facilitate sealing. In fact, the two tubulars could simply be expanded
together to effect a fluid-tight seal.
[0050] In operation, a tubular string having the features shown in Figure 18 at an upper
end thereof would be used as follows: The tubular string 601 would be lowered into
a wellbore until the circumferential area 602 of an upper portion 600 thereof is adjacent
that area where the smaller diameter tubular 600 is to be expanded into a larger diameter
tubular 650 therearound. Thereafter, using an expansion tool as described herein,
that portion of the smaller diameter tubular 600 including area 602 is expanded into
frictional contact with the tubular 650 therearound. With the weight of the tubular
string 601 supported by the outer tubular 650, any fluid can be circulated through
an annular area defined between the tubulars 600, 650 or between the outside of the
smaller tubular and a borehole therearound. As fluid passes through the annular area,
circulation is possible due to the apertures 610 in the wall of the smaller diameter
tubular 600. Once the circulation of cement is complete, but before the cement cures,
that portion of the smaller diameter tubular 600 bearing the circumferential grooves
620 with elastomeric seal rings 622 is expanded. In this manner, a hanging means is
created between a first smaller diameter tubular 600 and a second larger diameter
tubular 650 whereby cement or any other fluid is easily circulated through the connection
area after the smaller diameter tubular is supported by the outer larger diameter
tubular but before a seal is made therebetween. Thereafter, the connection between
the two tubulars is sealed and completed.
[0051] While foregoing is directed to the preferred embodiment of the present invention,
other and further embodiments of the invention may be devised without departing from
the basic scope thereof, and the scope thereof is determined by the claims that follow.
1. A method of joining tubulars in a wellbore comprising:
running a first tubular (315) into the wellbore, an upper end of a section of the
first tubular (315) being supported by a bearing (310) on the run-in string (305),
the run-in string (305) having a hydraulically actuatable, radially extendable, rotatable
cutting tool (100) and a hydraulically actuatable, radially extendable expansion tool
(400) disposed thereon below the bearing (310) and within the first tubular (315),
and the expansion tool (400) being disposed below the cutting tool (100);
using the expansion tool (400) to expand a portion of the first tubular (315) into
a portion of a second tubular (320) fixed in the wellbore, whereby, after expanding,
the first tubular (315) is supported in the wellbore by interference between the first
tubular (315) and the second tubular (320);
using the cutting tool (100) to sever the first tubular (315) above that portion of
the first tubular (315) which has been expanded in the expanding step; and
removing the run-in string (305) and an upper portion of the first tubular (315) from
the wellbore after the expanding and severing steps.
2. The method of claim 1, further including the step of expanding a remaining portion
of a lower portion of the first tubular after the first tubular is severed.
3. The method of claim 1 or 2, wherein the first tubular is a liner and the second tubular
is a casing fixed in the wellbore.
4. The method of claim 1, 2 or 3, wherein the first tubular and the second tubular are
initially joined by the expanding step only in certain locations and not circumferentially,
thereby maintaining a fluid path between the first tubular and the second tubular.
5. The method of any preceding claim, wherein in the severing step the cutting tool separates
the first tubular into an upper and a lower portion through rotational and radial
force.
6. The method of any preceding claim, wherein the bearing permits rotation of the run-in
string in relation to the first tubular.
7. An apparatus for joining a first tubular (315) to a second tubular (320) in a wellbore,
comprising:
a run-in string (305) disposable in the wellbore, the run-in string (305) having a
bearing (310) for supporting an upper end of a section of the first tubular (315);
a hydraulically actuatable, radially extendable, rotatable cutting tool (100) disposed
on the run-in string (305), the cutting tool (100) being configured for transversely
severing the first tubular (315) therearound into an upper and a lower portion; and
a hydraulically actuatable, radially extendable expansion tool (400) disposed on the
run-in string (305) below the cutting tool (100), the expansion tool (400) being configured
for expanding the first tubular (315) therearound.
8. The apparatus of claim 7, wherein the bearing further permits rotation of the run-in
string in relation to the first tubular.
9. The apparatus of claim 7 or 8, wherein the cutting tool has a body with at least one
opening formed in a wall thereof and at least one cutter assembly disposed within
the body, the cutter assembly including at least one hydraulically actuatable, radially
extendable cutter arranged to contact the inside wall of the first tubular therearound,
and wherein the expansion tool has a body with at least one opening formed in a wall
thereof and at least one roller assembly disposed within the body, the roller assembly
including at least one hydraulically actuatable, radially extendable roller arranged
to contact the inside wall of the liner therearound and, through radial force and
rotational movement, to sever the first tubular.
1. Verfahren zum Verbinden von Rohren in einem Bohrloch umfassend :
Eintreiben eines ersten Rohres (315) in das Bohrloch, wobei ein oberes Ende eines
Abschnitts des ersten Rohres (315) von einem Lager (310) auf dem Einführungsstrang
(305) getragen wird, wobei der Einführungsstrang (305) ein hydraulisch betätigbares,
radial ausziehbares, drehbares Schneidwerkzeug (100) und ein hydraulisch betätigbares,
radial ausziehbares Aufweitwerkzeug (400) hat, die auf demselben unterhalb des Lagers
(310) und innerhalb des ersten Rohres (315) angeordnet sind, wobei das Aufweitwerkzeug
(400) unterhalb des Schneidwerkzeugs (100) angeordnet ist,
Benutzen des Aufweitwerkzeugs (400), um einen Abschnitt des ersten Rohres (315) in
einen Abschnitt eines zweiten Rohres (320) das in dem Bohrloch fixiert ist aufzuweiten,
wobei nach dem Aufweiten das erste Rohr (315) durch den Eingriff zwischen dem ersten
Rohr (315) und dem zweiten Rohr (320) getragen wird,
Benutzen des Schneidwerkzeugs (100), um das erste Rohr (315) oberhalb des Abschnitts
des ersten Rohres (315) das in dem Aufweitungsschritt aufgeweitet wurde abzutrennen,
und
Entfernen des Einführungsstrangs (305) und eines oberen Abschnitts des ersten Rohres
(315) aus dem Bohrloch nach dem Aufweitungs- und Abtrennungsschritt.
2. Verfahren nach Anspruch 1, des Weiteren umfassend den Schritt des Aufweitens eines
restlichen Abschnitts eines unteren Abschnitts des ersten Rohres nach dem Abtrennen
des ersten Rohres.
3. Verfahren nach Anspruch 1 oder 2, wobei das erste Rohr ein Liner und das zweite Rohr
ein Futterrohr ist die im Bohrloch fixiert sind.
4. Verfahren nach Anspruch 1, 2 oder 3, wobei das erste und das zweite Rohr anfangs nur
in bestimmten Regionen durch den Aufweitungsschritt verbunden werden und nicht um
den Unfang, wodurch ein Fluidweg zwischen dem ersten und dem zweiten Rohr erhalten
bleibt.
5. Verfahren nach einem der vorhergehenden Ansprüche, wobei in dem Abtrennungsschritt
das Schneidwerkzeug das erste Rohr in einen unteren und einen oberen Abschnitt durch
eine Dreh- und Radialkraft trennt.
6. Verfahren nach einem der vorhergehenden Ansprüche, worin das Lager die Drehung des
Einführungsstranges in Bezug auf das erste Rohr ermöglicht.
7. Vorrichtung zum Verbinden eines ersten Rohres (315) mit einem zweiten Rohr (320) in
einem Bohrloch, umfassend:
einen Einführungsstrang (305) der in einem Bohrloch vorhanden ist, wobei der Einführungsstrang
(305) ein Lager (310) hat, um ein oberes Ende eines Abschnittes des ersten Rohres
(315) zu tragen,
ein hydraulisch betätigbares, radial ausziehbares, drehbares Schneidwerkzeug (100),
das auf dem Einführungsstrang (305) angeordnet ist, wobei das Schneidwerkzeug (100)
ausgebildet ist das erste Rohr (315) transversal um den Umfang in einen oberen und
einen unteren Abschnitt zu durchtrennen, und
und ein hydraulisch betätigbares, radial ausziehbares Aufweitwerkzeug (400), das auf
dem Einführungsstrang (305) unterhalb des Schneidwerkzeugs (100) angeordnet ist, wobei
das Aufweitwerkzeug (400) dazu ausgebildet ist das erste Rohr (315) dortherum aufzuweiten.
8. Vorrichtung nach Anspruch 7, wobei das Lager des Weiteren die Drehung des Einführungsstranges
in Bezug zum ersten Rohr ermöglicht.
9. Vorrichtung nach Anspruch 7 oder 8, wobei das Schneidwerkzeug einen Körper aufweist,
mit mindestens einer Öffnung die in einer Wand davon gebildet ist und mindestens einer
innerhalb des Körpers angeordneten Schneidanordnung, wobei die Schneidanordnung mindestens
einen hydraulisch betätigbaren, radial ausziehbaren Fräser hat der eingerichtet ist,
um die Innenwand des ersten Rohres dortherum zu kontaktieren, und wobei das Aufweitwerkzeug
einen Körper aufweist mit mindestens einer Öffnung die in einer Wand davon gebildet
ist und mindestens eine Rollenbaugruppe die innerhalb des Körpers angeordnet ist,
wobei die Rollenbaugruppe wenigstens eine hydraulisch betätigbare, radial ausziehbare
Rolle hat, die eingerichtet ist um die Innenwand des Liners drumherum zu kontaktieren
und das erste Rohr durch eine Dreh- und Radialkraft abzutrennen.
1. Procédé pour joindre des tubes dans un puits de forage, comprenant les étapes suivantes:
faire entrer un premier tube (315) dans le puits de forage, une extrémité supérieure
d'une section du premier tube (315) étant supportée par un palier (310) sur le train
de sonde de descente (305), le train de sonde de descente (305) comportant un outil
de coupe rotatif (100) à actionnement hydraulique et extensible radialement et un
outil d'expansion extensible radialement et à actionnement hydraulique (400) qui y
sont disposés en dessous du palier (310) et dans le premier tube (315), l'outil d'expansion
(400) étant disposé en dessous de l'outil de coupe (100);
utiliser l'outil d'expansion (400) pour étendre une portion du premier tube (315)
dans une portion d'un deuxième tube (320) fixé dans le puits de forage, le premier
tube (315) étant alors, après son extension, supporté dans le puits de forage par
l'interférence produite entre le premier tube (315) et le deuxième tube (320);
utiliser l'outil de coupe (100) pour couper le premier tube (315) au-dessus de la
portion du premier tube (315) qui a été étendue dans l'étape d'extension; et
retirer le train de sonde de descente (305) et une partie supérieure du premier tube
(315) du puits de forage après les étapes d'extension et de coupe.
2. Procédé selon la revendication 1, comprenant en outre l'étape consistant à étendre
une portion restante d'une portion inférieure du premier tube après que le premier
tube a été coupé.
3. Procédé selon la revendication 1 ou 2, dans lequel le premier tube est une colonne
perdue et le deuxième tube est un tubage fixé dans le puits de forage.
4. Procédé selon la revendication 1, 2 ou 3, dans lequel le premier tube et le deuxième
tube sont initialement joints lors de l'étape d'extension à certains endroits seulement
et pas de manière circonférentielle, maintenant ainsi un chemin de fluide entre le
premier tube et le deuxième tube.
5. Procédé selon l'une quelconque des revendications précédentes, dans lequel, dans l'étape
de coupe, l'outil de coupe sépare le premier tube en une portion supérieure et une
portion inférieure par l'intermédiaire d'une force rotationnelle et radiale.
6. Procédé selon l'une quelconque des revendications précédentes, dans lequel le palier
permet la rotation du train de sonde de descente par rapport au premier tube.
7. Dispositif pour joindre un premier tube (315) à un deuxième tube (320) dans un puits
de forage, comprenant:
un train de sonde de descente (305) disponible dans le puits de forage, le train de
sonde de descente (305) comportant un palier (310) pour supporter une extrémité supérieure
d'une section du premier tube (315);
un outil de coupe rotatif à actionnement hydraulique et radialement extensible (100)
disposé sur le train de sonde de descente (305), l'outil de coupe (100) étant configuré
pour couper transversalement le premier tube (315) sur sa circonférence pour obtenir
une portion supérieure et une portion inférieure; et
un outil d'expansion radialement extensible et hydrauliquement actionnable (400) disposé
sur le train de sonde de descente (305) en dessous de l'outil de coupe (100), l'outil
d'expansion (400) étant configuré pour étendre le premier tube (315) sur sa circonférence.
8. Dispositif selon la revendication 7, dans lequel le palier permet en outre une rotation
du train de sonde de descente par rapport au premier tube.
9. Dispositif selon la revendication 7 ou 8, dans lequel l'outil de coupe a un corps
qui comporte au moins une ouverture formée dans une paroi de celui-ci et au moins
un ensemble de coupe disposé dans le corps, l'ensemble de coupe incluant au moins
un coupeur radialement extensible et à actionnement hydraulique agencé pour contacter
la paroi interne du premier tube sur sa circonférence, et dans lequel l'outil d'expansion
a un corps qui comporte au moins une ouverture formée dans une paroi de celui-ci et
au moins un ensemble de cylindres disposé dans le corps, l'ensemble de cylindres incluant
au moins un cylindre radialement extensible et hydrauliquement actionnable agencé
pour contacter la paroi interne du tubage sur sa circonférence et pour couper le premier
tube par l'intermédiaire de la force radiale et du mouvement rotationnel.